Kinder Morgan Inc

NYSE:KMI

Earnings Call Transcript 2022-Q2

[Operator]

Welcome to the quarterly earnings conference call. Today’s call is being recorded. If you have any objections, you may disconnect at this time. All participants are in a listen-only mode until the question-and-answer portion of today’s call.

I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

[Rich Kinder, Executive Chairman]

Thank you, Jordan. And as I always do, before we begin, I’d like to remind you that KMI’s earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities Exchange Act of 1934 as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors, which may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

Let me start by saying that in these turbulent and volatile times, it seems to me that every public company owes its investors a clear explanation of its strategy and its financial philosophy. In these days, platitudes and unsubstantiated hockey stick growth projections don’t play well. To my way of thinking, despite the pronouncements of celebrities, fortune may not favor the brave so much as it favors the cash. The ability to produce sizable amounts of cash from operations should be viewed as a real positive in picky investments. But I believe that generating cash is only part of the story. The rest is dependent on how that cash is utilized.

At Kinder Morgan, we consistently produce solid and growing cash flow, and we demonstrated that once again this quarter. At the Board and the management level, we spend a lot of time and effort deciding how to deploy that cash. As I’ve said ad nauseam, our goals are to maintain a strong investment-grade balance sheet, fund expansion and acquisition opportunities, pay a handsome and growing dividend and further reward our shareholders by repurchasing our shares on an opportunistic basis. As Steve and the team will explain in detail, we used our funds for all of those purposes in the second quarter.

To further clarify our way of thinking, we approved new capital projects only when we are assured that these projects will yield a return well in excess of our weighted cost of capital. Obviously, in the case of new pipeline projects, most of the return is normally based on long-term throughput contracts, which we are able to negotiate prior to the start of construction. But we also look at the long-term horizon, and we’re pretty conservative in assumptions on renewal contracts after expiration of the base term and on the terminal value of the investment. That said, we are finding good opportunities to grow our pipeline network as demonstrated by our recent announcement of the expansion of our Permian Highway Pipeline, which will enable additional natural gas to be transported out of the Permian Basin.

So, if we’re generating lots of cash and using it in productive ways, why isn’t that reflected at a higher price per KMI stock? Or to use that old phrase, "If you’re so smart, why ain’t you rich?" In my judgment, market pricing has disconnected from the fundamentals of the midstream energy business, resulting in a KMI yield -- dividend yield approaching 7%, which seems ludicrous for a company with the stable assets of Kinder Morgan and the robust coverage of our dividend.

I don’t have an answer for this disconnect. And it’s easy to blame factors over which we have no control, like the mistaken belief that energy companies have no future or the volatility of crude prices, which, in fact, have a relatively small impact on our financial performance. Specific to KMI, some of you may prefer that we adopt a "swing for the fences" philosophy, rather than our balanced approach, while others may think we should be even more conservative than we are.

To paraphrase Abe Lincoln, I know we can’t please all of you all the time, but I can assure you that this Board and management team are firmly committed to return value to our shareholders and that we will be as transparent as possible in explaining our story to you and all of our constituents. Steve?

[Steve Kean, CEO]

We’re having a good year. We’re projecting to be nicely above plan for the year and substantially better year-over-year Q2-to-Q2, as Kim and David will tell you. Some of the outperformance is commodity price tailwinds, but we’re also up on commercial and operational performance. And here are some highlights.

Our capacity sales and renewals in our gas business are strong. Gathering and processing is also strong, up versus planned and up year-over-year. Existing capacity is growing in value. I’ll give you an example. After years of talking about the impact of contract roll-offs, we’re now seeing value growth in many places across our network. One recent example on our Mid-Continent Express Pipeline, we recently completed an open season where we awarded a substantial chunk of capacity at maximum rates. Those rates are above our original project rate.

While not super material to our overall results, I think it’s a stark and good illustration of the broader trend of rate and term improvements on many of our renewals in the Natural Gas business unit.

Second, at CO2, SACROC production is well above plan. And of course, we are benefiting from higher commodity prices in this segment. The product segment is ahead of plan and terminals is right on plan. We’re facing some cost headwinds, mostly because of added work this year. While costs are up, we’re actually doing very well in holding back the impacts of inflation. It’s hard to measure precisely, but based on our analysis, we are well below the headline PPI numbers that you’re seeing. And actually, we appear to be experiencing less than half of those increases. That’s due to much good work by our procurement and operations teams, and much of this good performance is attributable to our culture. We are frugal with our investors’ money.

A few comments on capital allocation. The order of operations remains the same as it has been for years. First, a strong balance sheet, we expect to end this year a bit better than our 4.5x debt-to-EBITDA target, giving us capacity to take advantage of opportunities and protect us from risk. As we noted at our Investor Day this year, having that capacity is valuable to our equity owners.

Second, we invest in attractive opportunities to add to the value of the firm. We have found some incremental opportunities and expect to invest about $1.5 billion this year in expansion capital. And notably, we added an expansion of our Permian Highway Pipeline. We picked up Mas Energy, that’s M-A-S, a renewable natural gas company. And we’re close on a couple of more nice additions to our renewable Natural Gas business. We are finding these opportunities and others all at attractive returns well above our cost of capital.

Finally, we return the excess cash to our investors in the form of a growing well-covered dividend and share repurchases. So far this year, we have purchased about 16.1 million shares while raising the dividend 3% year-over-year.

As we look ahead, we have a $2.1 billion backlog, 75% of which is in low-carbon energy services. That’s natural gas, RNG as well as renewable diesel and associated feedstocks in our Products and Terminals segment. Again, all of these are attractive returns. And I want to emphasize, as we’ve said, I think many times now, our investments in the energy transition businesses we have done without sacrificing our return criteria, a nice accomplishment.

In Natural Gas, in particular, we are focused on continuing to be the provider of choice for the growing LNG market where we expect to maintain and even expand on potentially our 50% share. And in natural gas storage, which is highly cost-effective energy storage in a market that will continue to need more flexibility. Again, we are having a very good year. We are further strengthening our balance sheet, finding excellent investment opportunities and returning value to shareholders, and we are setting ourselves up well for the future. Kim?

[Kim Dang, President]

Thanks, Steve. Starting with the Natural Gas business segment for the quarter. Transport volumes were down about 2%. That’s approximately 0.6 million dekatherms per day versus the second quarter of 2021. That was driven primarily by reduced volumes to Mexico as a result of third-party pipeline capacity added to the market, a pipeline outage on EPNG and continued decline in the Rockies production. These declines were partially offset by higher LNG deliveries and higher power demand.

Deliveries to LNG facilities off of our pipelines averaged approximately 5.8 million dekatherms per day, about 16% higher than the second quarter of ‘21 but lower than the first quarter of this year due to the Freeport LNG outage. Our current market share of deliveries to LNG facilities remains around 50%. We currently have about 7 Bcf a day of LNG feed gas contracted on our pipes. And we’ve got another 2.6 Bcf a day of highly likely contracts where projects have been FIDed but not yet built or where we expect them to FID in the near term.

We’re also working on a significant amount of other potential projects. And given the proximity of our assets to the planned LNG expansions, we expect to maintain or grow that market share as we pursue those opportunities. Deliveries to power plants in the quarter were robust, up about 7% versus the second quarter of ‘21.

The overall demand for natural gas is very strong. And as Steve said, that drives nice demand for our transport and storage services. For the future, we continue to anticipate growth in LNG exports, power, industrial and exports to Mexico. For LNG demand, our internal and Wood Mac numbers project between 11 and 15 Bcf a day of LNG demand growth by 2028.

Our natural gas gathering volumes in the quarter were up 12% compared to the second quarter of ‘21. Sequentially, volumes were up 6% with a big increase in the Haynesville volumes up 15% and Eagle Ford volumes up 10%. These increases were somewhat offset by lower volumes in the Bakken. Overall, our gathering volumes in the Natural Gas segment were budgeted to increase by 10% for the full year, and we’re currently on track to exceed that number.

In our Products Pipeline segment, refined products volumes were down 2% for the quarter versus the second quarter of 2021. Gasoline and diesel were down 3% and 11%, respectively, but we did see a 19% increase in jet fuel demand. For July, we started the month down versus 2021 on refined products, but we have seen gasoline prices decrease nicely over the last month or so.

Crude and condensate volumes were down 6% in the quarter versus the first quarter of ‘21. Sequential volumes were down 2% with the reduction in the Bakken volumes more than offsetting an increase in the Eagle Ford.

In our Terminals business segment, our liquids utilization percentage remains high at 91%. Excluding tanks out of service for required inspections, utilization is approximately 94%. And liquids throughput during the quarter was up 4% driven by gasoline, diesel and renewables.

We have seen some rate weakness on renewals -- contract renewals in our hub terminal impacted by the backwardation in the market, just like we saw some marginal benefit when the curve was in a contango position a couple of years ago. Although we were hurt in the quarter by lower average rates on our marine tankers, all 16 vessels are currently sailing under firm contracts, and rates are now at pre-COVID levels.

On the bulk side, overall volumes increased by 1%, driven by pet coke and coal, and that was somewhat offset by lower steel volume. In the CO2 segment, crude, NGL and CO2 volumes were down compared to Q2 of ‘21, but that was more than offset by higher commodity prices. Versus our budget, crude, NGL and CO2 volumes as well as price on all these commodities are all expected to exceed our expectations.

Overall, we had a very nice first half of the year. We currently project that we will exceed our full year 2020 plan DCF and EBITDA by 5%. And we’ve approved a number of nice new projects, including the PHP expansion and eventually past Phase 1.

With that, I’ll turn it over to David Michels.

[David Michels, CFO]

Thanks, Kim. For the second quarter of 2022, we’re declaring a dividend of $0.2775 per share, which is $1.11 per share annualized, up 3% from our 2021 dividend. And one highlight before we begin the financial performance review. As Steve mentioned, we took advantage of a low stock price by tapping our Board-approved share repurchase program. Year-to-date, we’ve repurchased 16.1 million shares for $17.09 per share. We believe those repurchases will generate an attractive return for our shareholders. Our savings from the current dividends alone without regard to terminal value assumptions or dividend growth in the future is 6.5%, a nice return to our shareholders.

Moving on to the second quarter financial performance. We generated revenues of $5.15 billion, up $2 billion from the second quarter of 2021. Our associated cost of sales also increased by $1.7 billion. Combining those two items, our gross margin was $254 million higher this quarter versus a year ago. Our net income was $635 million, up from a net loss of $757 million in the second quarter of last year, but that includes a noncash impairment item for 2021. Our adjusted earnings, which excludes certain items including that noncash impairment, was $621 million this quarter, up 20% from adjusted earnings in the second quarter of 2021.

As for our DCF performance, each of our business units generated higher EBDA than the second quarter of last year. Natural Gas -- the Natural Gas segment was up $69 million with greater contributions from Stagecoach, which we acquired in July of last year; greater volumes through our KinderHawk system; favorable commodity price impacts on our Altamont and Copano South Texas systems. And those are partially offset by lower contributions from CIG.

The Product segment was up $6 million driven by favorable price impacts, partially offset by lower crude volumes on Hiland and HH as well as higher integrity costs. Our Terminals segment was up $7 million with greater contributions from expansion projects placed in service, a gain on a sale of an idled facility and greater coal and pet coke volumes. Those are partially offset by lower contributions from our New York Harbor terminals and our Jones Act tanker business versus the second quarter of last year.

Our CO2 segment was up $60 million, driven by favorable commodity prices, more than offsetting lower year-over-year oil and CO2 volumes as well as some higher operating costs. Also adding to that segment were contributions from our Energy Transition Ventures renewable natural gas business, Kinetrex, which we acquired in August of last year.

The DCF in total was $1.176 billion, 15% over the second quarter of 2021. And our DCF per share was $0.52, up 16% from last year. It’s a very nice performance.

On to our balance sheet. We ended the second quarter with $31 billion of net debt and a net debt to adjusted EBITDA ratio of 4.3x. That’s up from year-end at 3.9 times, although that 3.9 times includes the nonrecurring EBITDA contributions from the Winter Storm Uri event in February 2021. The ratio at year-end would have been 4.6 times excluding the Uri EBITDA contributions. So, we ended the quarter favorable to our year-end recurring metric.

Our net debt has decreased $185 million year-to-date, and I will reconcile that change to the end of the second quarter. We’ve generated year-to-date DCF of $2.631 billion. We’ve paid out dividends of $1.2 billion. We’ve spent $500 million on growth capital and contributions to our joint ventures. We’ve posted about $300 million of margin related to hedging activity. Through the second quarter, we had $170 million of stock repurchases. And we’ve had approximately $300 million of working capital uses year-to-date, and that explains the majority of the year-to-date net debt change.

And with that, I’ll turn it back to Steve.

[Steve Kean, CEO]

All right. Thank you. So, we’ll open up to the Q&A part of the session. And as a reminder, as we’ve been doing, we ask you to limit your questions to one question and one follow-up. And then, if you’ve got more, get back in the queue and we will get to you. And here in the room, we have a good portion of our management team. And as you ask your questions, I’ll let you hear directly from them on your question -- about questions about their businesses. So, Jordan, you would open up the Q&A.

[Operator]

Thank you. [Operator Instructions] Our first question comes from Jeremy Tonet from JP Morgan.

[Jeremy Tonet, JP Morgan]

So, I guess, Bitcoin shouldn’t be on the high on the list for organic growth projects anytime soon, I’m taking it. But moving on to the Permian, I just want to see as far as takeaway is concerned, what’s your latest look there as far as when tightness could materialize? And at the same time, with GCX, just wondering if -- what it takes to reach FID there if the basin is tight. Then could this be a near-term event?

[Steve Kean, CEO]

Tom?

[Tom Martin, President, Natural Gas Pipelines]

Yes. So, I think with the projects, including ours that have been FIDed and are proceeding in the construction mode, that there may be a near-term tightness. But once those projects go into service, we feel like the market is pretty well served until the latter part of the decade. So, I think the next projects will likely come in -- will need to be FIDed sometime in ‘24, maybe ‘25. And there still may be opportunities in the near term for GCX. We are in several discussions with a lot of additional customers there for pockets of capacity, especially to serve LNG markets. But I think -- for now, I think the markets, at least on a near term to intermediate term, are pretty well served.

[Steve Kean, CEO]

And GCX is fast to market, has as a compression expansion. The FID is in the middle part of the decade or 27 to 30 months to complete roughly.

[Jeremy Tonet, JP Morgan]

Got it. So I just want to confirm there, back half of decade next pipe, you said there as far as beyond what’s currently out there?

[Tom Martin, President, Natural Gas Pipelines]

That sounds right.

[Jeremy Tonet, JP Morgan]

Got it. And real quick, just on the renewable natural gas. Just wanted to see if you could provide more details on the acquisition here Mas CanAm. As far as the economics, what type of renewable credits were kind of baked in their expectations? And should we expect kind of more acquisitions of this nature going forward? Is this an area that’s ripe for consolidation for Kinder to go after? Just wondering broader thoughts there.

[Steve Kean, CEO]

Anthony?

[Anthony Ashley, President, CO2 & Energy Transition Ventures]

Yes. So, the acquisition, we’re excited about it. It’s 3 landfill gas assets, 1 RNG facility in Arlington, and that’s the bulk of the value here, $355 million. We had two medium-BTU facility in Shreveport and Victoria as well. It is a little bit different from the Kinetrex deal. It’s -- because there’s an operating asset, it’s largely derisked. Arlington has favorable royalty arrangements in place, long-term contract into the transportation market, so there’s when exposed here. And the long-term EBITDA multiple here is around 8 times.

[Steve Kean, CEO]

Okay. And the prospects for additional?

[Anthony Ashley, President, CO2 & Energy Transition Ventures]

Yes. And so I think, as Steve mentioned, we have line of sight for some additional growth. There are some opportunities on the M&A side, but I think largely, we’ll be looking to grow organically in the future.

[Jeremy Tonet, JP Morgan]

Got it. That’s helpful. Thank you.

[Steve Kean, CEO]

You’re right, Jeremy. Bitcoin is not even in the shadow backlog.

[Jeremy Tonet, JP Morgan]

Didn’t think so. Thank you.

[Operator]

Our next question comes from Jean Ann Salisbury with Bernstein.

[Jean Ann Salisbury, Bernstein]

Hi. Have your operations had to adjust for the Freeport outage? Can you talk about if you’re seeing more flows in to Louisiana or Mexico are getting absorbed by Texas weather, or are you just kind of not getting paid from some of it if they did force majeure?

[Tom Martin, President, Natural Gas Pipelines]

Yes. So, I would say fairly immaterial financial impact to us. But as far as an impact to the market, we’re certainly seeing the basis market in the Katy Ship Channel area weaken with the additional volumes that are hitting the Texas market. I think it helps support storage, Gulf Coast storage more broadly. But certainly, has been at least partially offset by the extreme power demand that we’ve been seeing here in Texas and along the Gulf Coast. And I would say just with the connectivity with the interstate pipeline grid between intras and interstates that those volumes are getting pretty well dispersed.

[Jean Ann Salisbury, Bernstein]

Great. And then, my second question is very long term. I’m getting asked about this from generalists, and I want to make sure I’m getting it right. Just kind of want to understand refined product types is the common concern that I’m hearing. If we play out an energy transition scenario, we’re flowing them and 15 years is much lower than today, let’s say. Can you talk about what would happen to the pipe revenue for refined product pipes? Is it mostly cost of service-based or negotiated or some of those?

[Steve Kean, CEO]

Yes, Dax?

[Dax Sanders, President, Products Pipelines]

Yes. I guess, I would say, first of all, it depends on where -- sort of where it happens. I mean, I think from an economic protection perspective, we have the ability to -- making protection on the pipes to be able to take into account decreased volumes to increase rates to be able to protect us.

And so, I think the place that’s probably been most progressive on this has been California with the conversation about potentially banning the internal combustion engine. But if you look at that, really what that gets to is road fuels consumed in the state of California, and we obviously transport a lot of products out of there to other states. And we did an analysis on that. And that came to about 11% of products EBDA on a 2019 basis.

So, if you look at the place, that’s probably the most progressive on it. That’s really kind of what you’re looking at from our segment’s perspective. And that’s before you put in place tariff protection. So, that’s the way we’d look at it.

[Steve Kean, CEO]

Yes. So Jean, there’s a bit of a contrast here between how things work on the products pipeline and, for example, how things work on the natural gas pipelines. We do tend to do a lot of negotiated rate transactions on the natural gas pipeline grid. In the regulated interstate -- well, even intrastate, refined products pipelines, those are typically -- those are -- they are cost of service-regulated common carrier pipelines. We just recently settled a significant rate case, a long-running rate case on our SFPP system. We have an ongoing one on the interstate in the CPUC business. But if you think about these pipes economically, they really are the cheapest and best way to move the product from point A to point B. And so, there is good strength in their market position.

And so yes, if there was a decrease in volume, you would go in and you’d say, "I have lower volume units. I’m spreading the same cost of service over a lower number of barrels, and I want a rate increase." Now, that’s not how we run the railroad, and that’s not something that we’ve had to do with the one exception of the California intrastate market. But, it is a bit of a different dynamic between refined products pipelines and the natural gas pipelines.

[Kim Dang, President]

The other thing -- we can move renewable diesel through our pipes. To the extent that that gets replaced, renewable diesel can go through. And also sustainable aviation fuel could be moved through our pipes as well. So those were replacement products.

[Operator]

Our next question comes from Colton Bean with Tudor, Pickering, Holt & Co.

[Colton Bean, Tudor, Pickering, Holt & Co.]

On the guidance increase, it looks like an EBITDA step-up of $350 million or better. I guess, first, are there any offsets at the cash flow level that results in DCF also being 5%, or is that just a function of rounding? And then second, I think you all flagged about $750 million of discretionary cash on the original budget. Should we assume the guidance increase is additive to that total, including the $100 million bump in CapEx last quarter?

[David Michels, CFO]

The offsets are the items that are unfavorable between EBITDA and DCF for us are interest expense and sustaining capital. Interest expense versus our budget is just up because short-term rates are meaningfully above what we had budgeted, and the longer-term rates are also up a little bit. And then, the sustaining capital, we have some incremental class change costs that we had -- that we didn’t budget for and a little bit of inflation costs increasing our sustaining capital.

In terms of the available capacity that we talked about at the beginning of the year, the $750 million was based on available capacity given our budgeted EBITDA and assumed spend for the year. Our EBITDA is up nicely. So, that’s increased the available balance sheet capacity that we have. But we’ve also spent -- we’re also increasing our spend a little bit more than what we had budgeted given the Mas transaction. We have a couple of additional projects in our discretionary spend that Steve talked about. And we’ve repurchased some shares that weren’t in our budget. So overall, our available capacity is still higher than what we had budgeted, but we’ve also spent a fair amount more than what we had budgeted as well.

[Colton Bean, Tudor, Pickering, Holt & Co.]

Great. And then, David, maybe just sticking on the financing side of things. I think you all noted that you had locked in roughly $5 billion of your floating rate exposure through the end of this year. Any updates or shifts in how you’re thinking about managing that heading into 2023?

[David Michels, CFO]

Yes. We haven’t had a similar opportunity to lock in favorable rates for 2023. So, we’re very pleased that we locked it in for this year. It’s been almost a $70 million benefit to us this year. But -- and we’ll continue to look at ways that we could potentially mitigate that going into 2023. But so far, we haven’t found any favorable opportunities to do that because we just continue to see as we get through the year more pressure on short-term rates going into next year. With some of the recessionary pressures that we’ve seen in the market, I think that’s starting to loosen up a little bit. So, we’ll continue to take a look at it, but nothing yet.

[Operator]

Our next question comes from Chase Mulvehill with Bank of America.

[Chase Mulvehill, Bank of America]

I guess, I wanted to come back and kind of hit on guidance a little bit. I guess, just specifically on gathering volumes, I think you guided up originally 10%. And I think you noted you’re going to be above that, and you kind of mentioned that in last quarter’s conference call as well. And you’ve obviously given us the sensitivity here that we can use towards your guidance. So, how much do you think that gathering volumes will be up now? And I guess, maybe what’s included in the updated guidance?

[Kim Dang, President]

So, we think it’s going to be up -- I think it’s around 13% versus the 10%, and it is included in our updated guidance.

[Chase Mulvehill, Bank of America]

Okay, great. And can I ask kind of -- maybe it’s a little more technical question, but around kind of brownfield Permian egress expansions. How should we think about the timing and how this incremental capacity will pull through incremental volumes? Basically, what I’m asking is, will you be able to pull through more volumes gradually as you add each incremental compression station or will you ultimately all start the incremental production at once at the end when you have all the compression stations added?

[Tom Martin, President, Natural Gas Pipelines]

No. I think it’s more of a light-switch experience as we approach November, December ‘23. There’ll be certainly test volumes, additional volumes that we do test along the way. But I think to get to the ultimate delivery point where the customers want to go, that will all happen November, December ‘23.

[Operator]

Our next question comes from Michael Blum with Wells Fargo.

[Michael Blum, Wells Fargo]

I wanted to maybe just start with the opening comments about the stock price. I’m just wondering if you could expand a little more there. And I guess, specifically, are there any specific actions that you’re contemplating that to impact the stock price here?

[Rich Kinder, Executive Chairman]

Well, I’ve learned a long time ago that the ability of management team to influence the stock price is pretty remote. But let me just say and the point of what I was trying to do is I think there -- it’s not just Kinder Morgan. I think there’s a tremendous disconnect between the way the market is valuing midstream energy companies. For instance, there’s much more of a correlation with crude oil prices in our stock than there ought to be. As we tell everybody at the beginning of the year, exactly how much the impact is per dollar of change in crude and natural gas prices. And of course, that’s a relatively small number of lessons as you get further into the year. That’s just one example of, I think, kind of a knee-jerk reaction in the market.

I think the best thing we can do as a management and Board is to stress again and again the strength of our cash flow and the fact that we’re using it wisely. And I think we demonstrated that in this quarter in the way we’ve deployed our cash. So, that’s our game plan, pretty simple and not very imaginative really. But I think in the long run -- maybe we’re the tortoise versus the hare. But in the long run, I think we get rewarded for the kind of performance we have produced now quarter after quarter after quarter.

[Michael Blum, Wells Fargo]

All right. Great. Thank you for those comments. I guess, my second question -- well, first of all, Anthony, congratulations on the expanded responsibilities. And maybe I’m reading into this, but my question is really with the promotion to run both, energy transition and CO2. Can I read anything into that about maybe enhanced prospects for carbon capture, you’re kind of bringing these two things onto the same roof?

[Steve Kean, CEO]

Look, I think we feel like there are some synergies there, and I’ll ask Anthony to expand on that. But I mean we’ll use the same geologist for carbon capture and sequestration as we do for CO2. I mean, we’ve been sequestering CO2 for decades, and we use it in connection with the enhanced oil recovery operations obviously. But it’s the same technology, if you will. And so, we think there is synergy there, and there are a few others. But I’ll turn it over to Anthony to answer the rest.

[Anthony Ashley, President, CO2 & Energy Transition Ventures]

Yes. I mean, obviously, Jesse had a great opportunity, and we wish him well. And it’s a great opportunity for me. And I’ve inherited a really great team. So I appreciate that.

I don’t think you’re going to see anything materially different from the way we kind of run things moving forward. As Steve mentioned, I think as we have been moving forward with ETV, it’s become more and more apparent there’s a lot of overlap, especially with the CO2 group, so a lot of technical experience there that we’ve been using. And we’ll be further integrating those groups and taking advantage of that. And I think that will provide some nice commercial synergies down the road. But, we don’t have anything special to announce. And I don’t think you’re going to see the way we run the CO2 business or ETV to be materially different from the way Jesse was doing.

[Steve Kean, CEO]

Yes. And I think the further integration benefits, we have the same operations organization. So some of these where it was a small company we acquired, and we have other acquisitions that we’re integrating. And so having a common operations platform, I think, will be very helpful.

We also have a common project management platform, which is also helpful. And of course, we’ve always had a centralized procurement organization. And bringing the power of that procurement organization to bear on these development opportunities, I think all that will pay dividends. But this is not leaning into the CCUS. That will -- we think there are opportunities there. We think they’re coming but coming slowly. And there’s some resolution of 45Q tax credit levels and things like that, that still needs to unfold. But anyway, this business fits together and so it stays together.

[Operator]

Our next question comes from Keith Stanley with Wolfe Research.

[Keith Stanley, Wolfe Research]

First, wanted to ask just on the next wave of LNG projects. So, you have this $600 million project you’re announcing on TGP and SNG tied to Plaquemines. Can you talk to which specific LNG projects we should track more closely that you see more opportunity to potentially provide gas services to? And is there any way to frame the potential investment opportunity in dollars around new LNG projects in the next five years? So, should we expect other $600 million-type investment opportunities tied to the next wave of projects?

[Tom Martin, President, Natural Gas Pipelines]

Yes. I mean, -- so I don’t want to call winners and losers in here. But I mean I think the way you would think about this is those that have been successful to this point already, I think have a good chance of being more successful over time by virtue of expansions of their existing footprints. There’s certainly some new entrants that we’re very excited to be partnering with to grow along with Texas, Louisiana Gulf Coast.

And again, I think given the proximity of our footprint, we’re talking to all of these developers and working with all of them and looking for ways to expand our footprint and even build some greenfield projects to support their growth. So, we feel very bullish about this opportunity. And we think there’s significant investment opportunity here over the next three to five years.

[Kim Dang, President]

Yes. And so, as a result, some of the opportunities, we’ll be able to utilize capacity on our existing system or add compression and they’ll be very, very efficient. And then some of the opportunities will require greenfield -- some level of greenfield development. And so it will be a combination of both.

[Rich Kinder, Executive Chairman]

And I think the macro opportunity here is incredible. I’ll come back to what Kim said, depending on which expert you listen to, the projections are between now over the next five years or so, you’re going to have 11 to 13 or 14 Bcf a day in growth in LNG. We fully expect to be able to maintain our 50% share, which we have now. That’s an incredible increase in throughput, a lot of which is attributable to the present system that we have in place along the Texas and Louisiana Gulf Coast. It’s an incredible green shoot for Kinder Morgan.

[Keith Stanley, Wolfe Research]

And separate question, I guess, kind of revisiting Michael’s question from earlier. So, the Company hasn’t really done material stock buybacks since really kind of 2018. And it looks like you did 270 million. The average price implies that was kind of done over the past month for the most part. So I know you’ve talked to being bullish on the stock price, but just any other color on what changed in the market or just the decision process? Because it’s a pretty material step-up in buybacks in a brief period. And how you’re thinking about that, I guess, over the balance of the year since you still have available capacity?

[Steve Kean, CEO]

Maybe I’ll start and, David, you can fill in. But we kind of planned to look at how the year was unfolding over the first quarter and to get a lot of confidence around it. We live in uncertain times, right? So, we were -- we have good, strong cash flows that are secured by contracts and all of that. We’ve got a lot of stability in our business. But kind of wanted to see how the year was unfolding. And so that was then -- things look good. We talked about it looking good in Q1. I thought we were going to be up on guidance, but didn’t quantify it for you. And so, that was a good opportunity. We had to use some capacity, and we stuck to our opportunistic approach to share repurchases, and that’s exactly what we expect to continue to do. And we would expect -- you can’t call it for sure, but we’d expect to have opportunities to do more through the course of the year.

[David Michels, CFO]

And one thing I -- I think Steve covered it. I just -- we would balance some of the additional spend that we’ve already incurred with the additional available capacity that we generated because of our EBITDA outperformance. So, we’ll look at a balance of those items along with the opportunistic share repurchases for the rest of the year.

[Operator]

Our next question comes from Marc Solecitto with Barclays.

[Marc Solecitto, Barclays]

With inflation tracking where it is, that should be a nice tailwind for your products business. Just wondering if you can maybe comment on how that interplays with the broader macro and any competitive dynamics across your footprint and your ability to fully pass that through.

[Steve Kean, CEO]

Dax, why don’t you start?

[Dax Sanders, President, Products Pipelines]

Yes. No. Based on where PPI, we follow the FERC methodology on our FERC policy at 2 [ph] pipes, which right now is PPI FG minus 0.21%. And we implemented the rate increase on July 1st of 8.7% across our assets. And based on where it’s tracking right now, I think the -- assuming we would -- PPI continues where it is and that we would implement the full thing, which is what we would expect, it’s somewhere in the neighborhood of 15% next year.

[Marc Solecitto, Barclays]

Great. Appreciate the color there. And then on your CapEx budget, the $1.5 billion for this year, should we think the bulk of CapEx spend on PHP will come in ‘23? Or is that -- any context into what the CapEx cost component of these expansions could be? And then on Evangeline Pass, could we see CapEx move higher this year subject to definitive commercial agreements, or that’s to mostly come in later years?

[David Michels, CFO]

They’re going to be later, yes, partly because we’ve got a regulatory process to go through. And -- but on PHP, it’s going to be mostly in ‘23.

[Kim Dang, President]

And the ‘23 [ph] will be incorporated in the $1.5 billion.

[Operator]

Our next question comes from Michael Lapides with Goldman Sachs.

[Michael Lapides, Goldman Sachs]

Hey, guys. Congrats on a good quarter, and congrats to Tom and to Anthony for the movement around the greater opportunities. One kind of near-term question. Refined products pipeline volume or throughput during the quarter, a little bit weak on gasoline, a little bit weak on diesel. Can you just kind of talk about whether that’s geographic specific to you, whether that’s more just general demand destruction due to price, especially on the diesel side?

[Steve Kean, CEO]

Dax.

[Dax Sanders, President, Products Pipelines]

Yes. We are seeing a little bit of demand destruction a bit across the system, I would say, on road fuels. Jet fuel, as you would expect, as you see naturally a pretty strong increase. I mean, I think the EI numbers on jet are about 18. As Kim said, we’re about 19 on diesel. You saw a larger decrease on our assets. EIA was just right around 3%. We were closer to 11%. But I will remind you on diesel, we are still within 2% of where we were in 2019. We saw a big jump last year on diesel volume. So, while we’ve seen come off compared to Q2 of last year, it’s still pretty robust. But we have seen a little bit of demand destruction. But I think you’ve seen gasoline prices across the country come off for, I want to say, 35 days straight. So, we’ve seen customer response. We’ve also seen price response.

[Michael Lapides, Goldman Sachs]

Got it. And then, maybe a follow-up for Anthony. Just thinking about the landfill gas deal that you announced today. And I think you made a comment that kind of build multiple, call it, roughly 8 times. Is that kind of a year one in that, therefore, as we think about it over time, that build multiple actually gets better over time as production there ramps, or is that what you think kind of a steady state would be? And how do you compare that to the EBITDA and returns on capital that you get out of the natural gas -- kind of the core gas pipeline business?

[Anthony Ashley, President, CO2 & Energy Transition Ventures]

Yes. I mean, it ramps up to 8 and gets better from there. So there is growth at this landfill, which is really primarily driven by the Arlington asset. We have perpetual gas rights there, and there is a potential expansion that we have down the road on that asset. And so, the EBITDA multiple gets better over time. I would say the 8 times is more the -- an average over the medium term there.

With regards to how we think about nat gas, I think we’d look at it on different types of opportunities. It’s a very different type of investment. So, I’m not sure it’s necessarily comparing apples to apples. But I think in terms of the opportunity here as we think about our RNG portfolio, these are assets which are largely derisked. There are in operations today. There are, as I said, long-term gas rights here with Arlington as an expansion and growth opportunity. And so, I think it’s an attractive acquisition in terms of how we think about that in this space.

[Steve Kean, CEO]

And as a general comment, Michael, but as we said at the beginning, we have not had to sacrifice our return criteria and have not had to sacrifice the margin above our weighted average cost of capital to be able to invest in these things. We’ve been very selective about how we’ve entered this sector.

[Operator]

Our next question comes from Brian Reynolds with UBS.

[Brian Reynolds, UBS]

I’m curious just on Ruby Pipeline, if there’s any updates on the bankruptcy proceedings and if there are any initial thoughts on a near-term resolution as it relates to nat gas service and if there’s any commentary on potential long-term CO2 transport, given a regional peer looking to do the same.

[Steve Kean, CEO]

Yes. We’ll ask Kevin Grahmann, our Head of Corporate Development.

[Kevin Grahmann, Head, Corporate Development]

Yes. In terms of the bankruptcy proceeding, Ruby has in place an independent set of managers who have been managing a lot of the day-to-day on the proceedings. There has been some recent court activity around a time line proceeding forward around a potential 363 [ph] sale and just getting to a resolution of the case along a certain time line. So, that’s where it stands. I can’t comment on any specific negotiations or discussions with parties involved. I will point to our prior comments on this, which is anything that KMI does around Ruby is going to be in the interest of KMI shareholders.

I think as it relates to your question around potential conversion of CO2 service on the pipe, I think first, the pipe does continue to serve a need for the California market. And so, it is a pipe that has a good service and natural gas service today. But across our network, we are looking at repurposing opportunities. But I think our general view at this point is those are longer-dated opportunities.

[Brian Reynolds, UBS]

Great. I appreciate the color. And then a quick follow-up on the guidance raise just given some of the acquisitions during the year. Curious if you could just kind of break out organic raise versus the contribution from some of the acquisitions year-to-date. Thanks.

[David Michels, CFO]

Yes. I mean, I would say it’s -- I mean, we do have a little bit of benefit from commodity prices, but we also have the benefit from our underlying base business. And a lot of that has come from -- we’re seeing some attractive renewals in the Natural Gas business, and that’s really in multiple places. It’s on our Texas Intrastate business, it’s on NGPL, it’s growth in our gathering business. It’s -- so it’s really -- I think a lot of that is organic strength in those contracts as we roll off. There’s some contribution from expansion capital during the -- but a lot of that ends up getting budgeted for the year based on what we know going in. And a lot of what we do that we sanctioned in the year ends up benefiting subsequent years. So I think you can attribute it to commodity price tailwind and/or -- and just organic growth in the base existing footprint.

[Kim Dang, President]

Because things like Stagecoach, we budgeted expansions that we knew about before the year started, we budgeted. And most expansions that we found that we’re doing this year don’t come on until 2023 or 2024 and beyond.

[Brian Reynolds, UBS]

Great. That’s super helpful. And just for clarification, just for the original guide on the landfill acquisitions, was that included before? Or is that included in this kind of 5% raise? Thanks.

[Kim Dang, President]

Kinetrex was included in the budget and -- would be incremental -- I mean Mas would be incremental to the budget.

[Operator]

Our next question comes from Michael Cusimano from Pickering Energy Partners.

[Michael Cusimano, Pickering Energy Partners]

Two questions for me. First, just is it fair to assume that the declines on Hiland and HH were weather-related? And can you talk through like how that’s recovered and maybe how the volume growth outlook has changed, if any, going forward?

[Steve Kean, CEO]

Do you have an answer on the volumes, Dax?

[Dax Sanders, President, Products Pipelines]

Yes, definitely. On Hiland, I would say the overwhelming majority of it is. I mean, just to give you some of the numbers, and that was the unexpected storm that came through in April. We were doing roughly north of 200,000 barrels a day in -- prior to that, in April, we ended up doing 163,000 and then we averaged about 188,000 for the quarter, but we’re back in June doing roughly 207,000. So it was a big chunk of it. For HH, less. That has a lot more to do with the spreads out of the Bakken, but it was absolutely the issue for the period.

[Tom Martin, President, Natural Gas Pipelines]

And the gas lines have recovered back to sort of pre-outage levels.

[Michael Cusimano, Pickering Energy Partners]

Okay. That’s helpful. And then looking at the Terminals business. So you mentioned utilization and rates are down a little bit because of the backwardation. And then Jones Act sounds like it’s kind of troughed at this point. So, am I wrong in thinking that we’ve reached like -- maybe like a new base level for that segment, or are there other puts and takes that I need to think about?

[David Michels, CFO]

No, you’re correct. I mean, the rate degradation that we’ve seen is specifically just in the New York Harbor. We’ve seen rates actually return to the levels we saw last year in the Houston area, and we’re back to 100% utilization there. As it relates to APT, we saw a trough last year, rates descending into the mid-50s per day. And they are back into the mid-60s now. We’re 100% utilized. All of the vessels are moving, and we’re actually seeing an increase in term. Where we were around two-year term last year, we’re now looking at 6.2 years with likely renewals. So, the answer to your question, yes.

[Michael Cusimano, Pickering Energy Partners]

Okay. And with the gain of sale that you mentioned, that was excluded from the EBITDA that you reported?

[Steve Kean, CEO]

Gain on sale, was that excluded from EBITDA?

[Kim Dang, President]

No, it’s in EBITDA. So, we have a level -- a certain level, $15 million that -- anything that’s below $15 million, like a gain on sale or something like that, it stays in the DCF. Anything that is above that would -- we take out -- the nonrecurring in nature, we take out of DCF. We had a lower threshold for a long time. It created a lot of noise in our numbers and made things confusing for people. And so, we’ve raised that threshold, which I think it makes it simpler for our investors and also is better at excluding really the onetime items. Because from time to time, we do have some land sales and that -- and so I think the higher threshold just makes a lot of sense.

[Steve Kean, CEO]

So, smaller nonrecurring pluses and minuses now get reflected.

[Michael Cusimano, Pickering Energy Partners]

Okay, got you. And is that something that you will quantify in like your materials going forward?

[David Michels, CFO]

Amount of smaller nonrecurring items that are impacting our EBITDA and DCF, no, we won’t. We just look at growth. We’ll explain it like we are today, like on this land sale, we’ll explain the gains and losses, if they’re bit large enough to explain.

[Tom Martin, President, Natural Gas Pipelines]

We’ll continue to explain the ones that are larger nonrecurring items. So, it will continue to be carved out, but there’ll be less noise with this. But again, the smaller positives and negatives will flow through.

[Operator]

Our final question comes from Harry Mateer with Barclays.

[Harry Mateer, Barclays]

Just two for me. I think the first, now we’re at the midway point of the year, would like to get an update on how you’re navigating your refinancing plans. You’ve got some maturities coming due early next year. I think you could probably call them out late this year. So, how are you thinking about navigating that? And then, secondly, there was a line in the press release about expecting to meet or improve on the debt metric goal. And I just want to confirm that that’s referring to the 4.3 times budget rather than like a formal change to the approximately 4.5 times goal you guys have had for a couple of years. Thanks.

[David Michels, CFO]

Yes. No, that is referring to our ending the year better than our budgeted level. That’s what we currently expect. But with regard to kind of how we are navigating issuances and how we’re going to handle some of the maturities coming due, as I’m sure you’re aware, Harry, we’re through our maturities for 2022. We do have about a little bit north of $900 million in CP currently. So -- but that’s why we have a $4 billion credit facility to handle short-term needs like this from time to time. And since we have $3 billion plus of capacity available, we don’t have any rush to term that out. So we can be patient there. We’ll look to potentially turn that out some time in the near term. But we’ll be patient. We’ll wait for favorable conditions. And then next year, it is a $3.2 billion maturity year. So, it’s relatively large, but we got the full year to do it. And we have the revolving -- revolver capacity to manage timing that out, waiting for favorable market condition.

[Harry Mateer, Barclays]

Okay, got it. But the Company’s formal leverage target is still 4.5 times. Is that right, David?

[David Michels, CFO]

Approximately -- around 4.5 times. That’s right.

[Operator]

We have no more callers in the queue.

[Rich Kinder, Executive Chairman]

Okay. Well, thank you very much, Jordan, and thanks to everybody for listening in. Have a good day.

[Operator]

Thank you for your participation in today’s conference. You may disconnect at this time.